This invention relates to an in situ method for yielding a gas from a subsurface formation of hydrocarbon material. More specifically, the invention relates to the production of high quality Btu fuel gas from subsurface formations of carbonaceous materials and to the reduction of hydrogen sulfide present in the resulting gas, or in natural gas-bearing formations, by applying a controlled current from a direct source to the formation.
The production of gaseous and liquid hydrocarbons by in situ gasification of underground formations of carbonaceous substances, such as coal, oil shale, and the like has long been recognized as a means of avoiding the high costs and inefficiencies attendant fuel production by conventional methods which rely on underground mining operations to provide feed stocks.
Among the prior art methods which have been proposed for in situ gas production are those involving combustion of the carbonaceous material in the subterranean formation. In one such method, a combustion zone is established by depositing combustible material in fractures in the formation adjacent to a well-bore, and passing sufficient current between electrodes positioned in well-bores connected with the fractures so as to heat the combustible material to its ignition temperature. Combustion is supported by the injection of oxygen or air through the well-bore into the combustion zone. As the injection of the combustion-supporting medium continues, the combustion front is driven radially outwardly from the injection well along the fractures. Gaseous hydrocarbons driven out of the formation by the combustion process are recovered from a production well penetrating the formation. See, for example, Dixon, U.S. Pat. No. 2,818,118. Related combustion processes involving electrocarbonization of underground formations to achieve in situ gas production are disclosed in Sarapuu, U.S. Pat. No. 2,795,279 and Parker, U.S. Pat. No. 3,106,244.
Other proposed in situ gasification methods have involved the use of electrical energy to heat the formation directly. For example, Baker, U.S. Pat. No. 849,524, describes a pyrolytic method in which electric current is passed through an underground formation by means of conductors placed in well-bores penetrating the formation, thereby heating the formation and volatizing components thereof, which are recovered through one of the wells. Although the Baker patent does not give the conditions employed in carrying out the method, temperatures in excess of 650.degree. F. are generally necessary to produce fuel gas by pyrolysis of oil shale, tars and coal.
A related method specific to the treatment of oil shale formations is disclosed in Parker, U.S. Pat. No. 3,428,125. The method entails injecting an electrolyte into the formation through two or more well-bores and applying an electrical potential across the formation between the well-bores. An electric current passes through and heats the formation to a temperature sufficient to pyrolyze the hydrocarbons present in the oil shale, while back-pressure is maintained on the formation to prevent vaporization of the electrolyte.
Although the prior art methods referred to above demonstrate that electrical energy can be used successfully for the in situ production of fuel gas, those methods have some rather serious shortcomings.
Combustion processes produce gas which is diluted with combustion products, as well as nitrogen gas in those instances where air is employed to sustain combustion. Dilution occurs as a result of channeling or formation collapse which allows the diluents to break through the combustion front and become intermixed with the gases preceding it. These are natural consequences of combustion processes about which nothing can be done. Hence, while a relatively high Btu content gas is swept in front of the expanding combustion front, the effects of channeling and formation collapse are such that the average Btu value of the gas actually recovered by combustion processes is relatively low, generally on the order of several hundred Btu/cu. ft.
Electrical methods such as those described in Baker, U.S. Pat. No. 849,524 and Parker, U.S. Pat. No. 3,428,125 require that a temperature on the order of 500.degree. F. to 660.degree. F. be maintained in the underground formation for successful operation. The amount of energy required for heating the formation to within this range is substantial. As stated in the Parker patent, for example, an electrical potential in excess of 400 volts must be impressed across the well casings with sufficient back-pressure of up to 1530 psig. applied on the well-bores to maintain the required temperature in the formation. In view of the ever-increasing costs of electrical energy, the operating conditions of these prior art methods must be considered a severe drawback.
A recent article by Coughlin et al, Nature, Vol. 279, pp 301-03 (1979) reports on an improved electrical method for coal gasification. In this method, a coal slurry undergoes treatment in an electrochemical cell, which is divided into separate anode and cathode compartments, to produce essentially pure hydrogen at the cathode, and CO.sub.2, containing small amounts of CO (about 3% at steady-state) at the anode. The method is carried out at relatively moderate temperatures and electrical potentials. For example, lignite reportedly has been gasified at potentials from 0.85 to 1.0 volts at about 240.degree. F. While this method has been practiced on a laboratory scale, its commercial practicability has yet to be demonstrated. Moreover, even if operative on a commercial scale, the operating cost of such a method would be relatively high, since mined coal would be required for the feed stock. Further, the mixture of gases produced by this method has a lower Btu value than is acceptable for a fuel gas.
Treatment of sour gas, that is, gas having a relatively high concentration of hydrogen sulfide, usually takes place after the gas has been produced. The removal of hydrogen sulfide is of primary importance to refiners because, not only is hydrogen sulfide a catalyst poison for downstream processing, but environmental considerations dictate the removal of sulfur-containing components from fuel gases.
Among the prior art methods which have been proposed for removing hydrogen sulfide from gas streams and gas wells are those involving scrubbing sour gas at elevated temperatures with a regenerable sorbent. See, for example, Wheelock et al, U.S. Pat. No. 3,974,265. Related scrubbing processes are disclosed in Erickson, U.S. Pat. No. 4,207,298 and Moore, U.S. Pat. Nos. 4,086,323 and 3,919,390.
Other proposed methods involve scrubbing the gas streams with liquid solutions such as mixtures of ethanolamines or mixtures comprising anthraquinone disulfonic acids at a temperature of about 200.degree. to 300.degree. F. These processes typically incorporate some regenerable compound which also acts as an oxidant, oxidizing the hydrogen sulfide to sulfur.
These prior art processes for hydrogen sulfide removal have been limited in either application or efficiency for one reason or another. In particular, all the above processes are applied after the gas has been produced.
Other processes which have been reported for the scrubbing of hydrogen sulfide from sour gas prior to production have been applied in the wellbore during drilling by additions of reactants to the drilling mud. Ray et al. in an article entitled "Use of Reactive Iron Oxide to Remove Hydrogen Sulfide From Drilling Fluid" (Society of Petroleum Engineers of AIME SPE 7498 (1978)), report the use of iron oxide added to drilling mud to react with the hydrogen sulfide.
Garret et al in an article entitled "Chemicals Scavangers For Sulfides In Water Base Drilling Fluids" (Society of Petroleum Engineers of AIME SPE 7499 (1978)), also report the use of chemical scavangers for sulfides in water base drilling fluids.